In order to stimulate and more effectively produce hydrocarbons from oil and gas bearing formations, and especially formations with low porosity and/or low permeability, induced fracturing (called “frac operations”, “hydraulic fracturing”, or simply “fracing”) of the hydrocarbon-bearing formations has been a commonly used technique. In a typical hydraulic fracturing operation, fluid slurries are pumped downhole under high pressure, causing the formations to fracture around the borehole, creating high permeability conduits that promote the flow of the hydrocarbons into the borehole. These frac operations can be conducted in horizontal and deviated, as well as vertical, boreholes, and in either intervals of uncased wells, or in cased wells through perforations.
In cased boreholes in vertical wells, for example, the high pressure fracturing fluids exit the borehole via perforations through the casing and surrounding cement, and cause the formations to fracture, usually in thin, generally vertical sheet-like fractures in the deeper formations in which oil and gas are commonly found. These induced fractures generally extend laterally a considerable distance out from the wellbore into the surrounding formations, and extend vertically until the fractures reach a formation that is not easily fractured above and/or below the desired frac interval. The directions of maximum and minimum horizontal stress within the formation determine the azimuthal orientation of the induced fractures.
The high pressure fracturing fluids contain particulate materials called proppants. The proppants are generally composed of sand, resin-coated sand or ceramic particulates, and the fluid used to pump these proppant particulates downhole is usually designed to be sufficiently viscous such that the proppant particulates remain entrained in the fluid as it moves downhole and out into the induced fractures. After the proppant has been placed in the fracture and the fluid pressure relaxed, the fracture is prevented from completely closing by the presence of the proppants which thus provide a high conductivity flow path to the wellbore which results in improved production performance from the stimulated well.
Sometimes, a wellbore will need to be “gravel packed” before production from the well begins in order to prevent particles (typically referred to as formation fines) from entering the wellbore. Gravel packing is necessary in formations that contain individual sand grains that are not tightly cemented together. If the individual sand grains remain unconsolidated, when production of the formation begins, the force of fluid flow will tend to move the unconsolidated sand grains into the wellbore. Gravel packing prevents this problem. In gravel packing, proppant is placed in the annulus of a wellbore, next to the unconsolidated formation fines, essentially working as a filter between the wellbore and the formation. The proppant is held in place by a slotted screen which prevents the proppant (and formation fines) from migrating into the wellbore, while still allowing the formation fluids to do so. If the wellbore is cased, the casing is first perforated in order to establish communication between the wellbore and the formation. The gravel packing process is generally performed in all formations that are considered to have unconsolidated formation fines, like those commonly found in the Gulf of Mexico.
Water injection wells may also be gravel packed because when a water injection well is shut-in, there can be a pressure surge or flowback into the wellbore which might result in an immediate flow of formation fines into the well. If formation fines are allowed to flow into the well, the formation could become plugged, which would prevent the resumption of injection of water into the well.
Similarly, wellbores can also be “frac packed”. Frac packing involves the simultaneous hydraulic fracturing of a reservoir and the placement of a gravel pack in the annular region of the wellbore. In frac packing, a fracture is created using a high-viscosity fluid that is pumped into the formation at above the fracturing pressure. Gravel pack screens are in place at the time of pumping and function the same way as in a typical gravel packing operation. Creating the fracture helps improve production rates while the gravel pack prevents formation fines from being produced and the gravel pack screens prevent the proppants from entering the produced fluids. This method allows for high conductivity channels to penetrate deeply into the formation while leaving the area around the wellbore undamaged. More than 65% of the completions in the Gulf of Mexico use frac pack systems.
In each case, to maximize an increase in permeability and prevent proppant flowback, the proppant particulates can be consolidated inside the propped fracture or a gravel packed or frac packed region, forming a “proppant pack”. Typically, resin-coating the proppant particulates allows for consolidation of the particulates at downhole conditions of temperatures of about 150° F. or higher and a closure stress of about 1000 psi. However, some hydraulic fracturing, gravel packing and frac packing procedures are conducted at much lower temperatures and in the case of gravel packing, with no closure stress.
It is desirable that curable resin-coated proppants remain unconsolidated under storage conditions and in a wellbore, at temperatures up to 200° F., but at zero closure stress. It is also desirable to consolidate the proppant pack in the wellbore on demand. In the past, it has not been possible to produce a resin-coated proppant that meets all of these criteria. Therefore, a need exists for a resin-coated proppant that remains unconsolidated during storage and in the wellbore, but is capable of forming a consolidated proppant pack downhole and in a gravel packing process at low temperatures and confining stresses.